ASCERTAINING THE EFFECTS OF GASEOUS PORE PRESSURE AND NET CONFINING STRESS ON PERMEABILITY OF TIGHT CORES USING A NEW STEADY-STATE APPROACH

Subsurface engineering systems undergo large changes in pore pressure, which can have drastic effects on their ability to transport and store fluids. For rock samples retrieved from conventional reservoirs, standard core analysis procedures provide suitable estimates of petrophysical properties, such as porosity and permeability. However, performing similar investigations on low-permeability systems like shales and tight gas sands remains a challenge. Steady-state gas permeametry is considered the gold standard for analyzing low-permeability cores, but researchers often forgo it in favor of faster but less reliable methods. Attempting a conventional permeability test on a tight plug sample typically results in miniscule flow rates that only expensive, specialized equipment can measure directly because of the sample’s extremely low permeability. Furthermore, these time-consuming tests are best run multiple times under varying ranges of pore pressure and confining stress. Doing so allows one to anticipate suitably the changes in permeability that will occur because of the expected changes in reservoir conditions.

This study describes a new experimental design and data analysis algorithm that accounts for changes in permeability over the range of pore pressures and confining stresses that occur during processes like unconventional hydrocarbon recovery and geologic carbon sequestration. The experiment involves maintaining a near-constant pressure gradient across a core-plug sample and indirectly measuring the flow rate induced by that gradient using a differential pressure transmitter. Tests were performed on samples of the Marcellus (shale) and Oriskany (sandstone) formations over a wide array of pore pressures and net confining stresses using multiple gases (He, N₂, and CH₄). Permeability estimates acquired from these analyses deviate appreciably from those acquired using routine core analysis. Having a quantifiable understanding of how the permeability of the system may change during the various stages of subsurface activity should significantly enhance the ability to optimize design outcomes. This will ultimately lead to improved oil and gas recovery and better predictions of injectivity and storage capacity during supercritical CO₂ storage operations.